This invention relates to a process for gas-lifting fluids from within a well penetrating a subterranean formation. More particularly it relates to a process for gas-lifting fluids from within a well penetrating a liquid-dominated geothermal formation depleted by loss of pressure or fluid enthalpy.
Dissolved hydrocarbon gases present in the liquid phase in petroleum reservoirs are known to enhance recovery of oil by decreasing the density of the oil and decreasing the pressure differential within the wellbore for a given flowrate. The natural "lift" provided by dissolved gases facilitates recovery in the phase referred to as primary oil recovery or "solution gas drive." However, the natural "lift" provided by dissolved hydrocarbon gases during solution gas drive ceases as soon as the gases come out of solution, which is normally early in the life of the reservoir.
Injected gases have been used to simulate the lift effect of reservoir gases in a number of different situations. For instance, to prolong the high productivity levels achieved during the early stages of reservoir production, it is known to inject compressed gases, such as nitrogen, into the fluids in the wellbore. The injected gases simulate the "lifting" action of dissolved reservoir gases and thereby prolong the period of high oil production. Injection of light gases to increase production of fluids from reservoirs has also been used successfully in gas and water reservoirs. The process is typically referred to as "gas lift" because injected light gases generally reduce the density of the reservoir fluid while also increasing pressure in the wellbore, just as naturally occurring reservoir gases do. The increased wellbore pressure exerts sufficient additional pressure differential in the wellbore to push or "lift" reservoir fluids from the well. But injection of gases into a highly pressured well poses technical and practical difficulties.
To overcome the difficulties of providing compressed gases for injection into a highly pressured well, a liquid capable of generating a gas within the wellbore upon contact with reservoir fluids can be employed. U.S. Pat. No. 4,410,041 to Davies et al. discloses a procedure for generating nitrogen gas in situ from an aqueous liquid solution injected into the wellbore. To draw reservoir fluids from the wellbore, the gas-generating solution is injected as nearly as possible at the depth where production fluids are being extracted. The reduced density of fluids at the production zone in the wellbore caused by generation of gases enhances the flow of fluids out of the reservoir.
Gas lift has also been used to "kick-off" production from a gas well that is dead due to a head of liquid standing in the wellbore generating hydrostatic pressure. Injected "lift" gases are used to displace sufficient liquid from the well to reduce the hydrostatic pressure to a level less than the pressure exerted by production gases. Either compressed gases or a gas-generating solution can be employed. A similar procedure can be used to return gas wells to production that have been swamped by water incursions.
However, in producing geothermal wells, gas lift has been considered either useless or too difficult to be practical outside of the limited situation of initiating flow in a dead well. For instance, injection of air or liquid nitrogen has been used to initiate flow in a shallow geothermal well. As a result of the air lift, air-water flow is produced at the wellhead and replacement fluid flows into the well from the feedpoint. If the replacement fluids have sufficient enthalpy, fluids in the wellbore will boil and steam created by the boiling will create a self-sustaining discharge.
In this procedure a flexible rubber tubing is inserted during injection and rapidly retrieved from the well before the flow was built up to full capacity. If not rapidly retrieved, the tubing will usually be blown out of the well by the turbulence and force of the production flow, which can range as high as a million pounds per hour for a geothermal well under full production. Thus, continuous injection of lift gases or gas-producing liquids into producing geothermal wells has not proved feasible using injection tubings.
Beyond the difficulty of the injection tubing being blown out of the well once production is initiated, "gas lift" has been unsuccessful for sustaining normal flowrates in already producing geothermal reservoirs for two additional reasons. First, because production flowrates from geothermal reservoirs are many times as great as from typical petroleum reservoirs, the quantity of injection gases needed to sustain normal flow in most geothermal wells is many times as great as in a petroleum reservoir. Second, the force and turbulence of typical geothermal flow rates requires that continuous injection of gases be conducted at pressures too high to be economical.
An alternative method of increasing flow from depleted geothermal wells is to install downhole pumps. But declining geothermal reservoirs often require that the fluid be lifted from 2000 feet or more below the surface. Current pump design cannot lift from such depths. Moreover, unless the conditions of temperature and pressure in the reservoir are well below those at which flashing could occur in the pump, cavitation would quickly destroy the pump.
Yet the need exists for a method to increase production from depleted geothermal reservoirs. Production flowrates from depleted geothermal reservoirs are much lower than is desirable for economic energy production. Over the production life of a geothermal reservoir, a continuous decrease in reservoir pressure or in fluid enthalpy is usually observed. These changes in reservoir conditions typically cause a decline in production rate sufficient to make continued operation of the wall unprofitable long before its resources have actually been consumed. Accordingly, the need exists for a method of utilizing gas lift injection to increase production from depleted geothermal wells.